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24 Oilfield Review
Finding Value in Formation Water
Operators usually consider formation water an undesirable byproduct of hydrocarbon
production. However, samples and analysis of that same water can provide vital
information for the field development plan, including optimization of completion
design, materials selection and hydrocarbon recovery.
Medhat Abdou
Abu Dhabi Company for Onshore Operations
Abu Dhabi, UAE
Andrew CarnegieWoodside Petroleum
Perth, Western Australia, Australia
S. George Mathews
Kevin McCarthy
Houston, Texas, USA
Michael O’Keefe
London, England
Bhavani Raghuraman
Princeton, New Jersey, USA
Wei WeiChevron
Houston, Texas
ChengGang Xian
Shenzhen, China
Oilfield Review Spring 2011: 23, no. 1.Copyright © 2011 Schlumberger.
For help in preparation of this article, thanks to SherifAbdel-Shakour and Greg Bowen, Abu Dhabi, UAE; AhmedBerrim, Abu Dhabi Marine Operating Company, Abu Dhabi,UAE; Hadrien Dumont, Balikpapan, Indonesia; Will Haug,Cuong Jackson and Oliver Mullins, Houston; Chee KinKhong, Luanda, Angola; Cholid Mas, Jakarta; and ArturStankiewicz, Clamart, France.
InSitu Density, InSitu Fluid Analyzer, InSitu pH, MDT,Oilphase-DBR, PS Platform and Quicksilver Probe are marksof Schlumberger.
At the mention of unexpected formation water in
their wells, many oil and gas producers react with
alarm. Unanticipated water production, particu-
larly if it contains unwanted impurities, can
significantly reduce the value of a hydrocarbon
asset. It can accelerate equipment damage and
increase water handling and disposal costs. But
capturing a certain amount of formation water is
also valuable; water properties contain a wealth
of information that can be used to significantly
impact field economics.
1. Ali SA, Clark WJ, Moore WR and Dribus JR: “Diagenesisand Reservoir Quality,” Oilfield Review 22, no. 2(Summer 2010): 14–27.
2. Interstitial water is the water between grains. For moreon evaporites: Warren JK: Evaporites: Sediments,Resources and Hydrocarbons . Berlin, Germany:Springer, 2006.
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Spring 2011 25
Formation water analysis plays a role in
dynamic modeling of reservoirs, quantifying
reserves and calculating completion costs, includ-
ing how much will be spent on casing and surface
equipment—capital expenditures (capex). Water
analysis also helps operators estimate operating
expenditures (opex), such as the cost of chemical
injection. Quantifying water chemistry aids in the
understanding of reservoir connectivity and in
characterizing transition zones in carbonates,thereby impacting estimates of reservoir extent. It
helps development planners determine whether
new discoveries can be tied into existing infra-
structure and is crucial for designing water injec-
tion projects.
Formation water properties vary from one
reservoir to another as well as within reservoirs.
Water composition depends on a number of
parameters, including depositional environment,
mineralogy of the formation, its pressure and
temperature history and the influx or migration
of fluids. Consequently, water properties can
change over time as the water and rock interact,
and as reservoir fluids are produced and replaced
with water from other formations, injected water
or other injected fluids.
This article examines the causes of variation
in water composition and describes the value of
formation water analysis throughout reservoir
life, from exploration to development and pro-
duction. Examples from Norway, the Middle East,
the Gulf of Mexico and China illustrate methods
for collecting high-quality water samples and
show how formation water analysis both down-
hole and at surface conditions contributes to res-
ervoir understanding and development.
Water Composition
Most reservoir rocks are formed in water, by the
deposition of rock grains or biological detritus.
The water that remains trapped in pores as the
sediments compact and bind together is called
connate water; the water in the reservoir at the
time it is penetrated by a drill bit is called forma-
tion water. Connate water reacts with the rock to
an extent that depends on temperature, pres-
sure, the composition of the water and the miner-
alogy of the formation. Chemical and biologicalreactions may begin as soon as sediments are
deposited. The reactions can continue and accel-
erate as the formation is subjected to greater
pressure and temperature during burial. The
combined effects of these chemical, physical and
biological processes are known as diagenesis.1
Although a great deal of effort has gone into
studying the impact of diagenesis on rock forma-
tions, relatively little has been made to under-
stand how it affects the original fluid within the
rock—the water.
Connate water varies with depositional envi-
ronment. In marine sediments, it is seawater. In
lake and river deposits, it is freshwater. In evapo-
rite deposits, the interstitial water is high-
salinity brine (right).2 These water solutions con-
tain ionic components, including cations such as
sodium [Na +], magnesium [Mg2+], calcium
[Ca 2+], potassium [K +], manganese [Mn2+],strontium [Sr2+], barium [Ba 2+] and iron [Fe2+
and Fe3+]; anions such as chloride [Cl–], sulfate
[SO42–], bicarbonate [HCO3
–], carbonate [CO32–],
hydroxide [OH–], borate [BO33–], bromide [Br–]
and phosphate [PO43–]; and nonvolatile weak
acids. The water may also contain dissolved gases,
such as carbon dioxide [CO2] and hydrogen
sulfide [H2S], nitrogen, organic acids, sulfur-
reducing bacteria, dissolved and suspended solids
and traces of hydrocarbon compounds.
Concentrations of these components may vary
as water is expelled by compaction and as it reacts
with formation minerals. Some minerals react
easily. For example, the clay mineral glauconite
has approximately the following composition:
K 0.6Na 0.05Fe3+1.3Mg0.4Fe2+
0.2 Al0.3Si3.8O10(OH)2. If the
connate water is undersaturated in the compo-
nents of the clay, it will interact with the mineral
grain by ion exchange, leaching ions from the
glauconite into the aqueous solution. Other min-
erals, such as quartz [SiO2], have higher resis-
tance to dissolution and remain as grain matrix. If
the water is saturated with the rock’s ions, miner
als can precipitate and form new grains or grow
on existing grains. Water properties such as pH
and ion concentration are some of the factors tha
control or influence water-rock interactions.
Even after equilibrium is reached, water-rock
interactions continue. However, changes in tem
perature, pressure, depth and structural dip can
disrupt equilibrium, as can the migration and
accumulation of oil and gas, which force the
water deeper as the lighter hydrocarbons rise
through a formation. The influx of water from
other sources, such as meteoric water, aquifers
injected water and other injected fluids, can also
cause water properties to change (below).
> Salinity variations. Salinity of connate watervaries with depositional environment, increasingfrom the freshwater of rivers to seawater andbriny evaporite systems. Formation water, the
result of water mixing and other physical andchemical processes, can have a wide range ofsalinities. (Data from Warren, reference 2.)
Average river water
Water TypeSalinity, Partsper Thousand
0.11
Formation water 7 to 270
Seawater 35
Evaporite systems 35 to 350
> Water movement and processes that can influence the evolution offormation water. Composition of formation water originally filling asandstone layer can be modified by the addition of water from othersources (arrows), such as meteoric water and water expressed fromcompacting shales and salt. The water can also be altered by the influx ofmigrating hydrocarbons. Sealing faults and other flow barriers can createcompartments with different water compositions. On the other hand,conducting faults can facilitate flow.
Basement
Faults
Rain (meteoric water)
Sea
Shale
Hydrocarbonaccumulation
ShaleSalt
Sandstone
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26 Oilfield Review
Production of formation water is another
cause of disequilibrium; dissolved minerals and
gases may come out of solution as the fluid is
brought to the surface—especially in reaction to
sulfates introduced into the formation through
drilling fluid invasion or injection of seawater.
These losses of the dissolved components alter
the composition of the produced or sampled
water, so water recovered at the surface may not
represent the actual formation water in place. For
this reason it is important to collect and analyze
formation water under in situ conditions, and to
continue to do so as reservoir conditions change.
Applications of Water Analysis
Formation water is rich with information about
the rock in which it resides, and it can provide
crucial input to analyses during every stage in the
life of a reservoir. Early in field life, analysis of for-
mation water establishes the salinity and resistiv-
ity of the water for petrophysical evaluation.3
Archie’s water saturation equation, from which oil
saturation and reserves are most frequently com-puted from logs, requires formation water resistiv-
ity as an input. That value is often computed from
resistivity and porosity logging measurements
made in a water zone, where the water may not
have the same composition as the reservoir forma-
tion water in other zones. Analysis of formation
water samples from the oil leg is considered one
of the most reliable ways to obtain water salinity
and resistivity for saturation calculations.
Before the material for casing or production
tubing is selected, it is vital to evaluate the cor-
rosivity of the gas, oil and water to be produced.
Free gas in the formation may contain corrosive
constituents—such as H2S and CO2—and these
same constituents may be dissolved in the forma-
tion water. Wells producing such fluids at concen-
trations exceeding certain limits require casing
with special metallurgical formulations that will
resist corrosion, or treatment with corrosion-
inhibiting chemicals.4 Furthermore, pipelines
and surface facilities must be capable of handling
the produced water with its accompanying gases
(see “Pipeline to Market,” page 4). To design pro-
duction tubing, flowlines and surface facilities,
engineers must know the chemical composition
of the formation water. The water pH and salinity
values used in metallurgical calculations for
selection of tubulars must include values for
downhole conditions of reservoir pressure and
temperature and water composition.5
As reservoir fluids are produced, the accom-
panying pressure reduction may cause therelease of gas from solution and the precipitation
and deposition of solids in the reservoir pores
and on production tubing and downhole equip-
ment. For example, as pressure decreases, forma-
tion water liberates CO2 gas, water pH increases
and the solution becomes supersaturated with
calcium carbonate [CaCO3], which can result in
scale deposition that may eventually choke off
flow (left).6 Precipitation can be predicted through
modeling or laboratory experimentation if forma-
tion water chemistry is known.
Scale can also form when waters of different
compositions mix.7 For example, precipitation of
barium sulfate [BaSO4] or strontium sulfate
[SrSO4] solids is a common problem when sea-
water, which contains sulfates, is injected into
formations that contain barium or strontium. Italso occurs when sulfates from drilling-fluid
invasion interact with the formation water, and
is the primary reason behind recent industry
practices using low-sulfate drilling fluids. Such
scale may be deposited in the formation or in
production tubing.8 Partially blocked tubing can
sometimes be cleaned with workover tools that
deploy abrasives and jetting action. However, if
the scale is too thick, there is little that can be
done except to pull the tubing and replace it—at
significant cost.
Effective scale management is an important
issue for field development planning and can have
a direct impact on production viability, especially
in marginally economic fields.9 The formation
water’s potential to create scale when mixed with
injected water must be assessed if any part of a
field is to be produced with pressure support from
injected fluids. In several cases, operators have
had to change plans—for example, halting sea-
water injection and finding another, more costly
source for injection water—based on knowledge
of formation water properties.10
In assessing scaling potential, one of the
greatest uncertainties may be the formation
water composition and downhole properties.
Some companies have adopted water monitoring
as routine practice for scale-prone fields. For
example, Statoil monitors the composition of
water produced from the majority of its oil and
gas wells, and uses crossplots of the ratio of ion
concentrations to assist in defining producing
water zones.11 Sampling frequency depends on
the need: In cases of high scale potential, water is
sampled every one to two weeks.
An additional use of water modeling in
development planning is the optimization of
well-stream mixing and process sharing: whenproduction streams from several wells, espe-
cially subsea wells, are combined before being
piped to intermediate separators or processing
facilities. To minimize risk of pipeline scaling
and corrosion, operators must fully understand
the chemical interaction of produced water from
different sources before committing to large
capital expenditures.
> Scale buildup in production tubing. Scale causes reduced flow rates andcan, eventually, completely block production.
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Spring 2011 27
Formation water composition plays a role in
“souring,” a process in which H2S concentration
increases in the reservoir.12 In many cases, souring
is attributed to microbial activity; injected seawa-
ter provides a source of sulfate-reducing bacteria
(SRB) and the formation water supplies nutrients
in the form of low–molecular weight organic acids
known as volatile fatty acids (VFAs). The conse-
quences of reservoir souring are potentially costly.
Increased levels of H2S increase safety risks foroilfield personnel, decrease the sales value of pro-
duced hydrocarbons and increase corrosion rates
in downhole equipment and surface facilities. An
estimated 70% of waterflooded reservoirs world-
wide have soured.13 Understanding water proper-
ties and modeling their changes throughout
reservoir life help chemical engineers predict H2S
generation and make informed decisions regard-
ing materials selection and facility design. Low-
contamination water samples, therefore, are
essential to establish the level of VFAs in the for-
mation water.14
Variations in formation water composition
can also reveal compartmentalization—or lack
of hydraulic communication between adjacent
reservoir volumes—if the reservoirs have been
isolated long enough for their formation waters
to have reached different equilibrium states.
Understanding reservoir connectivity is impor-
tant for estimating the extent of aquifer sup-
port—the natural water drive present in many
reservoirs—and for planning development well
locations, formulating injection-related recovery
programs and detecting injection-water break-
through. Analysis of formation water, and in par-
ticular, comparison of its natural isotopic
composition with that of injection water, has
been used for monitoring waterfloods.15 Isotopes
act as tracers in the water to help reservoir engi-
neers identify high-permeability layers, fractures
and other causes of interwell communication.
Sampling Water Water samples can be collected by several meth-
ods. Samples of produced water can be obtained
at the wellhead or from surface separators, but
these may not be representative of formation
water if gases have evolved or compounds have
precipitated. However, these samples are useful
and are typically collected for production surveil-
lance. Surface samples are used to monitor
changes in water properties over time, to identify
breakthrough of injection water and to compare
with samples from other producing wells to
understand reservoir connectivity. Acquiring
such samples is less expensive than downhole
sampling and can be done more routinely. Water
samples can also be retrieved from preserved
core.16 However, samples recovered by this tech-
nique have undergone pressure and temperature
decrease, and therefore may not be representa-
tive of actual formation water.
During the exploration and appraisal stages,
when an operator builds an understanding of the
reservoir fluids and uses the data for modeling, it
is vital to have representative water samples.
Representative samples can be collected by a
wireline formation tester equipped with a probe
or dual packer, a pumpout module, downhole
fluid-analysis capabilities and sample chambers
The downhole water-sampling process begins
with a cleanup stage, in which fluid—initially a
mixture of mud filtrate and formation water—i
drawn from the formation through the probe into
the tool.17 As pumping time increases, the propor
tion of mud filtrate, or contamination, decreasesand the proportion of pure formation water in the
flowline increases.
If the optical or resistivity properties of the
filtrate are significantly different from those o
the formation water, optical fluid analyzers or
resistivity sensors located in the tool flowline can
measure the difference and thereby monitor con
tamination in real time. In the early stages o
cleanup, the water is not pure enough to collect
and it is returned to the borehole. When the con
tamination is below a designated level, the fluid
is directed into pressurized sample chambers
which are brought to the surface and transported
to a laboratory for analysis.18
The quality of samples acquired downhole
depends on the method of sampling and the type
of drilling mud used in the sampled zones. In
zones drilled with oil-base muds (OBMs), high
quality water samples can usually be obtained
because the mud filtrate is not miscible with the
formation water. Formation water and OBM typi
cally have different optical and resistivity proper
ties, allowing them to be distinguished by optica
3. Warren EA and Smalley PC (eds): North Sea FormationWaters Atlas . London: The Geological Society, GeologicalSociety of London Memoir 15 (1994).
4. For more on corrosion, see Acuña IA, Monsegue A,Brill TM, Graven H, Mulders F, Le Calvez J-L, Nichols EA,Zapata Bermudez F, Notoadinegoro DM and Sofronov I:“Scanning for Downhole Corrosion,” Oilfield Review 22,no. 1 (Spring 2010): 42–50.
5. Williford J, Rice P and Ray T: “Selection of Metallurgyand Elastomers Used in Completion Products to AchievePredicted Product Integrity for the HP/HT Oil and GasFields of Indonesia,” paper SPE 54291, presented at theSPE Asia Pacific Oil and Gas Conference and Exhibition,Jakarta, April 20–22, 1999.
6. Ramstad K, Tydal T, Askvik KM and Fotland P: “PredictingCarbonate Scale in Oil Producers from High TemperatureReservoirs,” paper SPE 87430, presented at the SixthInternational Symposium on Oilfield Scale, Aberdeen,May 26–27, 2004.
7. Mackay DJ and Sorbie KS: “Brine Mixing in Water-flooded Reservoir and the Implications for ScalePrevention,” paper SPE 60193, presented at the SecondInternational Symposium on Oilfield Scale, Aberdeen,January 26–27, 2000.
8. Bezerra MCM, Rosario FF, Rocha AA and Sombra CL:“Assessment of Scaling Tendency of Campos BasinFields Based on the Characterization of FormationWaters,” paper SPE 87452, presented at the SixthInternational Symposium on Oilfield Scale, Aberdeen,May 26–27, 2004.
For an overview of scaling causes and mitigation:Crabtree M, Eslinger D, Fletcher P, Miller M, Johnson Aand King G: “Fighting Scale—Removal and Prevention,”Oilfield Review 11, no. 3 (Autumn 1999): 30–45.
9. Graham GM and Collins IR: “Assessing Scale Risks andUncertainties for Subsea Marginal Field Developments,”paper SPE 87460, presented at the Sixth InternationalSymposium on Oilfield Scale, Aberdeen, May 26–27, 2004.
10. Graham and Collins, reference 9.
Andersen KI, Halvorsen E, Sælensminde T andØstbye NO: “Water Management in a Closed Loop—Problems and Solutions at Brage Field,” paper SPE65162, presented at the SPE European PetroleumConference, Paris, October 24–25, 2000.
11. Ramstad K, Rohde HC, Tydal T and Christensen D:“Scale Squeeze Evaluation Through Improved SamplePreservation, Inhibitor Detection and Minimum InhibitorConcentration Monitoring,” paper SPE 114085,presented at the SPE International Oilfield ScaleConference, Aberdeen, May 28–29, 2008.
12. Farquhar GB: “A Review and Update of the Role ofVolatile Fatty Acids (VFA’s) in Seawater InjectionSystems,” paper NACE 98005, presented at the 53rdNACE Annual Conference, San Diego, California, USA,March 22–27, 1998.
Mueller RF and Nielsen PH: “Characterization ofThermophilic Consortia from Two Souring Oil Reservoirs,”Applied and Environmental Microbiology 62, no. 9(September 1996): 3083–3807.
13. Elshahawi H and Hashem M: “Accurate Measurementof the Hydrogen Sulfide Content in Formation WaterSamples—Case Studies,” paper SPE 94707, presentedat the Annual Technical Conference and Exhibition,Dallas, October 9–12, 2005.
14. Elshahawi and Hashem, reference 13.
15. Carrigan WJ, Nasr-El-Din HA, Al-Sharidi SH andClark ID: “Geochemical Characterization of Injected andProduced Water from Paleozoic Oil Reservoirs in CentraSaudi Arabia,” paper SPE 37270, presented at theInternational Symposium on Oilfield Chemistry, Houston,February 18–21, 1997.
Danquigny J, Matthews J, Noman R and Mohsen AJ:“Assessment of Interwell Communication in theCarbonate Al Khalij Oilfield Using Isotope Ratio WaterSample Analysis,” paper IPTC 10628, presented at theInternational Petroleum Technology Conference, Doha,Qatar, November 21–23, 2005.
Smalley PC and England WA: “Reservoir Compartmen- talization Assessed with Fluid Compositional Data,”SPE Reservoir Engineering (August 1994): 175–180.
Ramstad et al, reference 11.
16. Smalley and England, reference 15.
17. Mud filtrate is the portion of the drilling fluid that invades the formation during the creation of mudcake on theborehole wall. The filtrate is driven into the formation by the pressure difference between the drilling mud and the formation fluid.
18. Creek J, Cribbs M, Dong C, Mullins OC, Elshahawi H,Hegeman P, O’Keefe M, Peters K and Zuo JY:“Downhole Fluids Laboratory,” Oilfield Review 21,no. 4 (Winter 2009/2010): 38–54.
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28 Oilfield Review
fluid analyzers and resistivity sensors. Water-base
mud (WBM) filtrate, on the other hand, has opti-
cal properties similar to those of the formation
water, so the two are difficult to distinguish by
color. Also, WBM is miscible with formation water
and can mix and react with it, leading to contami-
nated and unrepresentative water samples unless
special care is taken to pump for a long time to
collect uncontaminated samples.
The Quicksilver Probe focused extractiontechnology can collect virtually contamination-
free formation fluids, which is especially impor-
tant when sampling formation water in the
presence of WBM filtrate.19 The tool’s articulated
probe, which contacts the formation at the bore-
hole wall, draws filtrate-contaminated fluid to
the perimeter of the contact area, where it is
pumped into a discharge flowline. This diversion
preferentially allows pure reservoir fluid to flow
into the sampling flowline. The probe can be run
as a module combined with the InSitu Fluid
Analyzer tool in the MDT modular formation
dynamics tester.
Ideal sampling consists of collecting a single-
phase sample and keeping it in single phase as it
is brought to the surface and transported to the
laboratory. The Oilphase-DBR single-phase multi-
sample chamber (SPMC) uses a nitrogen charge
to maintain downhole pressure on the reservoir
fluid sample between the downhole collection
point and the laboratory. This practice ensures
that gases and salts remain in solution during the
trip from downhole to the laboratory, which may
not be possible with standard sample chambers.
Single-phase samples can also be obtained
from drillstem tests (DSTs). Usually, water is notintentionally sampled during a DST, but some
operators make special efforts to study water
composition and will collect DST water samples
for laboratory analysis.20
Formation water samples can be obtained
later in field life during production logging opera-
tions. However, obtaining formation samples
prior to production is crucial for recording the
baseline composition. The Compact Production
Sampler captures conventional bottomhole sam-
ples in producing wells. It can be run in any sec-
tion of the PS Platform production logging string,
conveyed by either slickline or electric line.
Once the samples have been retrieved, they
are transported to a laboratory and recondi-
tioned to downhole conditions before analysis,
described in a later section. The results are
entered in a multiphase equilibrium model—
various models are available commercially—to
predict downhole pH and the potential for corro-
sion, scale and hydrate formation.
Because of the lack of a pH measurement on
reconditioned samples, chemical engineers use
equilibrium modeling to predict pH under reser-
voir conditions. However, uncertainties in the
thermodynamic models for formation waters athigh temperatures and pressures, as well as
uncertainties associated with the possible pre-
cipitation of salts, can propagate errors into
scale and corrosion models. Furthermore, unless
tools such as the SPMC are used, changes in pres-
sure and temperature as the water sample is
transported uphole may induce phase changes
that are not always fully reversible during the
reconditioning process.21
Since pH is a key parameter in understanding
water chemistry and plays a major role in predict-
ing corrosion and scale deposition, obtaining reli-
able pH measurements on formation water at
downhole conditions has been a priority for oil-
field fluid specialists.
> Downhole pH measurement. Equivalent to a downhole litmus test, the InSitu pH module ( left ) uses a mix of pH-sensitive dyesand detects their color change as a function of pH. The spectroscopic detector measures optical density at two wavelengths:570 nm and 445 nm. Laboratory experiments conducted as part of this technology development showed that pH is a predictablefunction of the ratio of optical density at 570 nm wavelength to that at 445 nm ( top right ). The color of the water-dye mixtureranges from yellow at a pH of 2 to purple at a pH of 10 (bottom right ).
pH
O p t i c a l d e n s i t y r a t i o ( 5 7 0 : 4 4 5 )
2
0.1
1.0
10
4 6 8 10
ModelThree-dye mix
Experiment
Tool wall
Fluid
flow
Dye
injector
Spectroscopic
detector
Lamp
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Spring 2011 29
Measuring pH In Situ
Schlumberger researchers developed a method
for measuring pH downhole using pH-sensitive
dyes.22 The InSitu pH reservoir fluid sensor works
on the same proven principles as other downhole
optical fluid analyzers designed for hydrocarbon
analysis.23 One difference, though, is that the
InSitu pH module injects pH-sensitive dye into
the tool flowline, where it mixes with the fluid
being pumped from the formation (previouspage). The fluid mixture changes color according
to the water pH, and optical sensors quantify the
color change by detecting optical density at mul-
tiple wavelengths. The wavelengths of the optical
channels in the InSitu pH device have been
selected to detect the colors expected when
waters of pH from about 3 to 9 react with a dye
mixture selected for this range. The measure-
ment is similar to the well-known litmus test for
indicating pH, but the science and applications
were adapted to the high-pressure, high-temper-
ature conditions encountered downhole.
At early pumping times in WBM systems, the
flowline fluid is predominantly filtrate, but as
pumping continues, the contamination level—
the concentration of mud filtrate—decreases,
producing a water sample more representative of
formation water. If the WBM-filtrate pH is signifi-
cantly different from formation-water pH (typical
ranges are pH of 7 to 10 for WBM, pH of 4 to 6 for
formation waters), then the pH of the mixture
changes as contamination decreases (top right).
Monitoring this change helps interpreters quali-
tatively track water-sample purity in real time
before collecting the water sample. The pH mea-
surement using this method is estimated to be
accurate to within 0.1 pH units.
An operator util ized this measurement tech-
nique in two wells offshore Norway, each pro-
posed to be tied back to different existing floating
production platforms.24 Knowledge of both hydro-
carbon and water composition is crucial for the
implementation of tieback development plans. In
particular, water analysis is important for flow
assurance in the seafloor pipelines, and tieback
requires water compatibility with the process
equipment on the main platform and with waters
flowing through it from other wells. Well 1, an exploration well, was drilled with
WBM through an oil reservoir and into an underly-
ing water zone. During cleanup of the water zone,
several series of dye injection followed by pH mea-
surement showed a clear change of pH over time,
indicating reduced contamination of the fluid in
the flowline. Laboratory analysis of a tracer added
to the drilling fluid confirmed low WBM contami-
nation of 0.2% in the collected sample.
Well 2, an appraisal well drilled in a gas-
condensate field, was drilled with an OBM system
to facilitate high-quality water sampling. Before
collecting samples at three depths, the tool mea-
sured pH, each time with multiple readings. At
the shallowest measurement station, the fluid
analyzer indicated the tool flowline contained a
mixture of oil and formation water. However, the
oil and water segregated within the tool, and the
dye mixed only with the water, allowing the pH ofthe water slugs to be measured. The pH values
did not vary over time because the OBM filtrate
did not contaminate the formation water.
Laboratory analysis of the water samples
acquired from these wells quantified concentra-
tions of major components and physical proper-
ties at surface conditions. Chemical engineers
used these results as input for models to predict
pH at downhole conditions.
For the sample from Well 1, the simulated pH
value matched the downhole pH value within
0.03 units, giving reservoir engineers confidence
in the downhole measurement, the condition of
the sample and the modeling method (below).
In Well 2, the sample from the shallowest
level had similar downhole and simulated pH val-
ues, different by only 0.03 units, again validating
the downhole measurement, the condition of the
sample and the model. The middle sample, 3.8 m
[12.5 ft] deeper, showed a significant mismatch
of 0.39 pH units between the simulated and mea
sured values—a discrepancy several time
greater than the typical measurement accuracy
Confidence in the downhole measurement at thi
station comes from the averaging of 60 data
> Monitoring water cleanup in an Egyptian wellbefore sample collection. As the tool pumpedfluid from the formation into the flow line, pHmeasurements indicated the change in watercomposition. Early in the cleanup process, thefluid mixture had a high pH, indicatingpredominantly WBM filtrate. After about 6,000 sof pumping time, the pH leveled off to a lowvalue, signaling that the fluid had cleaned up toan acceptable level of purity for sample collection
p H
Pumping time, s
0 2,000 4,000 6,000 8,00
7.2
7.0
6.8
6.6
6.4
> Downhole and laboratory formation water measurements. The cleanformation water samples were analyzed in the laboratory. Chemicalengineers used the ion concentrations and physical properties measuredfrom the liquid and the composition of the gas as inputs (not shown) tomodels to predict pH at downhole conditions. Comparison of thesepredictions with downhole measurements shows reasonable matches in allcases except for the sample from Well 2 at X,Y29.8 m. The mismatch mayindicate a compromise in the integrity of the sample during transfer fromdownhole conditions to the laboratory.
1 Y,Y08.5 53.8 6.26 6.29
5.756.14139.0X,Y29.8
5.855.82134.0X,X26.02
2
5.826.02142.0X,Y49.92
Well Depth, m Temperature, °C Downhole pH Modeled pH
19. For more on the Quicksilver Probe method, see:Akkurt R, Bowcock M, Davies J, Del Campo C, Hill B,Joshi S, Kundu D, Kumar S, O’Keefe M, Samir M,
Tarvin J, Weinheber P, Williams S and Zeybek M:“Focusing on Downhole Fluid Sampling and Analysis,”Oilfield Review 18, no. 4 (Winter 2006/2007): 4–19.
20. O’Keefe M, Eriksen KO, Williams S, Stensland D andVasques R: “Focused Sampling of Reservoir FluidsAchieves Undetectable Levels of Contamination,”paper SPE 101084, presented at the SPE Asia Pacific Oiland Gas Conference and Exhibition, Adelaide, SouthAustralia, Australia, September 11–13, 2005.
21. It may have taken millions of years for the water toequilibrate with the host formation. Once equilibrium isdisturbed, it may not be regained in time for laboratoryanalysis.
22. Raghuraman B, O’Keefe M, Eriksen KO, Tau LA,Vikane O, Gustavson G and Indo K: “Real-TimeDownhole pH Measurement Using Optical
Spectroscopy,” paper SPE 93057, presented at theSPE International Symposium on Oilfield Chemistry,Houston, February 2–4, 2005.
23. Andrews RJ, Beck G, Castelijns K, Chen A, Cribbs ME,Fadnes FH, Irvine-Fortescue J, Williams S, Hashem M,Jamaluddin A, Kurkjian A, Sass B, Mullins OC,Rylander E and Van Dusen A: “Quantifying ContaminationUsing Color of Crude and Condensate,” Oilfield Review 13no. 3 (Autumn 2001): 24–43.
24. Raghuraman et al, reference 22.
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30 Oilfield Review
points with a standard deviation of 0.02 pH
units—well within the expected measurement
accuracy. The discrepancy between the in situ
measurement and the value obtained by model-
ing based on laboratory results may indicate a
compromise in the integrity of the sample during
transfer from downhole conditions to the labora-
tory, emphasizing the benefit of the real-time
measurement. The pH of the third sample from
Well 2 is within 0.2 units of the simulated value, which is a more acceptable match.
These tests demonstrated the capability and
accuracy of the real-time downhole pH measure-
ment. The tool is able to take multiple measure-
ments at each station to verify water purity
before sample collection. In addition, it can ana-
lyze pH at any number of depths without acquir-
ing samples.
Water Assumptions
Downhole water pH measurements have also
been used to resolve formation evaluation chal-
lenges in a Middle East carbonate field.25 In a
giant offshore field, Abu Dhabi Marine Operating
Company (ADMA-OPCO) hoped to identify unde-
pleted thin pay zones and track movement of the
oil/water contact (OWC) in the main reservoir.
The main reservoir has undergone decades of
production with water injection, but some thinzones have not been tapped yet, and they are
appraisal targets.
Most wells in the field, including the four
wells in this study, were drilled with WBM using
seawater as the base. The WBM and formation
water cannot be distinguished using resistivity,
but the formation water has low pH, from 5.0 to
5.6, compared with that of the WBM (greater
than 7.0). The WBM and formation water also
have markedly different strontium concentra-
tions, allowing them to be differentiated through
laboratory analysis, which was the standard prac-
tice before the availability of real-time pH mea-
surements. In Well A, a water sample was
collected by traditional methods and sent for
laboratory analysis; that sample provided a basis
for comparison with the results from the three
other wells.
Well C penetrated the main reservoir and sev-eral thin zones believed to be untapped. At one
station, a pH measurement was performed after
just a few liters of fluid had been pumped from
the formation. The fluid was expected to be rich
in WBM filtrate, and indeed, it exhibited a down-
hole pH of 7.3. Samples of the WBM were col-
lected for laboratory analysis at the surface.
Resistivity log analysis suggested this thin,
20-ft [6-m] layer had high mobile oil saturation
and could be a potential pay zone. Pressure tests
at three stations in the interval indicated low
mobility but were inconclusive on fluid density.
Downhole fluid analysis at the location with
the highest mobility detected tiny amounts of oil
flowing with water in the flowline. After about
280 L [74 galUS] of formation fluid had been
pumped through the tool, dye injection followed
by pH measurement yielded a pH of 5.1. From
previous experience with downhole measure-
ments in the field, interpreters concluded the
water was formation water, and samples were col-
lected. Subsequent laboratory analysis of the
strontium concentration confirmed the interpre-
tation that this sampling depth was in the oil-
water transition zone.
Furthermore, the small fractional flow of oil
detected in the downhole fluid analysis implies
that the oil saturation is only slightly higher than
the residual oil saturation, and that the sampling
depth is close to the OWC. This example demon-
strates the benefits of downhole fluid analysis in
characterization of complex limestone transi-
tion zones, especially in thin intervals where
pressure and resistivity log interpretations can
have uncertainties.
At the top of the main reservoir zone, fluid
content estimates—calculated using an
assumed value for formation water salinity—indicated high oil saturation (above left).
However, pressure measurements across the
interval suggested a formation fluid density
equivalent to that of water, contradicting the
interpretation of high oil saturation.
Downhole fluid analysis performed in the
middle of this zone, after several hundred liters
of fluid had been pumped from the formation,
Oil
Moved Hydrocarbon
Moved Hydrocarbon
Calcite
DolomiteWater
Water
Resistivity-Based Fluid Analysis Volumetric Analysis
50 100% %0 0
Oil
Formation Pressure, psi
0.2 2,000ohm.m
0.14,430 4,530 1,000
1.082 g/cm3 (water)
1.111 g/cm3 (water)
1.140 g/cm3 (water)
Deep
0.2 2,000ohm.m
R xo
0.2 ohm.m 2,000
Medium
Resistivity
mD/cP
Pretest Mobility
> Contradictory interpretations in a potential oil-bearing zone. High predicted oil saturation (left , greenshading) near the top of this zone is in contrast to the pressure measurements (right ), which exhibit agradient indicative of water (blue dots). Pink dots are measurements in low-mobility zones and were
excluded from the gradient calculation. In situ measurement of pH (not shown) supported aninterpretation of injection water breakthrough in this interval.
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Spring 2011 31
indicated only water in the tool flowline. Real-
time measurements of pH returned a value of
6.2—lower than that expected of WBM, but
higher than that of the anticipated formation
water. Because so much fluid had been pumped
from the formation before taking the pH mea-
surement, WBM contamination of the water was
expected to be low. Fluid analysts suspected that
the fluid was not formation water, but water from
a nearby injection well. This interpretation wascorroborated by laboratory analysis of three
water samples collected at this depth.
The injection-water breakthrough had gone
undetected during initial openhole logging
because the water had not been analyzed, and
default values of formation water salinity caused
the log interpretation to wrongly predict that the
zone contained high volumes of mobile oil. The
true salinity of the water in this zone is about
one-sixth that of the default formation water, dra-
matically changing the interpretation. Correctly
identifying water origin by measuring its pH in
situ can have significant implications in terms of
completion and production planning to minimize
water production.
Whence the Water?
Abu Dhabi Company for Onshore Operations
(ADCO) used the downhole pH measurement in a
production well to delineate the oil/water con-
tact, characterize the oil-water transition zone
and identify the sources of water in various lay-
ers.26 The low resistivity contrast between the
WBM and the formation fluid precluded using
resistivity to track filtrate contamination. Instead,
ADCO selected two other methods for monitoring
contamination: in situ pH and a colored tracer in
the WBM that allows quantitative estimates of
contamination before sample collection.
The first sampling station was at X,X51 ft,
near the bottom of the suspected oil-water transi-
tion zone. This was confirmed by the optical ana-
lyzer, which showed only water and no oil flowing
at this depth. Monitoring the pH and optical
responses of the colored tracer during the
cleanup phase showed a reduction in WBM con-
tamination with pumping time. The decrease in
contamination manifested as downward trends
in both the pH and in the optical density of the
tracer-doped mud (above). The pH dropped from
6.47 at high contamination to 5.7, which engi-
neers interpreted as the pH of the nearly clean
formation water.
At the next sampling station, 10 ft [3 m
above the first, the optical analyzer detected only
water until pumping time reached 7,443 s. At tha
time, oil appeared in the flowline, and by 12,700 s
the oil fraction had increased to 90% (below)
25. Xian CG, Raghuraman B, Carnegie AJ, Goiran P-O andBerrim A: “Downhole pH as a Novel Measurement Toolin Carbonate Formation Evaluation and ReservoirMonitoring,” Petrophysics 49, no. 2 (April 2008): 159–171.
26. Raghuraman B, Xian C, Carnegie A, Lecerf B, Stewart L,Gustavson G, Abdou MK, Hosani A, Dawoud A, Mahdi Aand Ruefer S: “Downhole pH Measurement for WBMContamination Monitoring and Transition ZoneCharacterization,” paper SPE 95785, presented at theSPE Annual Technical Conference and Exhibition, Dallas,October 9–12, 2005.
> Contamination monitoring in an ADCO well. As the tool pumped fluid from the formation at X,X51 ft, the optical sensor detected a decrease in thefraction of blue-colored WBM with pumping time, indicating a reduction inmud contamination of the formation water. Measurements of pH at four times show a drop from 6.47 to 5.7 as the fluid in the flowline cleans up.
W B M c o n t a m i n a t i o n ,
%
Pumping time, 1,000 s
100
80
60
40
20
H d
5.8
6.0
6.2
6.4
00 2 4 6 8 10
ContaminationpH
Oil/water contact
90% oil, 10% formation water
100% formation water X,X51 ft
Time, 1,000 s
pHOil
p H
O i l %
5.5
6.5
100
50
0
6.0
4 86 10
D e p t h ,
f t
X,X41
X,X51
X,X??
X,X41 ft
Time, 1,000 s
pHOil
p H
O i l %
05.5
6.5
100
50
0
6.0
4 8 12
> Constraining the oil/water contact. Measurements at two depths, X,X41 ftand X,X51 ft, narrow the OWC to somewhere between them. At the deeperstation, optical fluid analysis detected water only, and pH measurementsindicated the presence of formation water. At the transition-zone station,10 ft higher, optical fluid analysis detected water initially, but eventually oilarrived and increased in volume fraction to 90%. The pH measurement at this station showed the water to be a mixture of formation water and filtrate,confirming the presence of mobile formation water. Therefore, the OWC isconstrained to the 10-ft interval between these two stations.
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32 Oilfield Review
Without a pH measurement to characterize the
type of water, there is no way to know if the water
is WBM filtrate or formation water. The presence
of pure WBM filtrate implies the formation water
is immobile, while the presence of any formation
water implies that formation water is mobile at
this depth.
A pH measurement taken at 6,452 s, slightly
before the arrival of the oil, gave a value of
5.77, indicative of a WBM–formation water mix.Optical measurement of the colored tracer con-
firmed this interpretation. This implies that oil
and water are both mobile at this depth.
Therefore, the oil/water contact must be between
the two measurement stations, narrowing it to
between X,X41 and X,X51 ft.
In another ADCO example, a well was drilled
to determine the source of water appearing in
nearby oil-producing wells. The new well, drilled
with OBM to simplify water sampling, penetrated
six limestone zones. The shallowest, Zone 1, con-
tained only oil; Zone 2 contained oil and water,
and the bottom four zones were water bearing.
ADCO wanted to know if the water produced
from the second layer was coming from the flank
of the reservoir through Zone 3, or from the
deeper zones.27
Of the water zones, Zone 5 was too tight to
flow, but in the other three the formation tester
measured downhole pH and collected pressur-
ized samples for laboratory analysis.
The downhole pH measurements indicated
that the water in Zone 4 was significantly differ-
ent from that in the other zones, and modeling
based on laboratory findings confirmed this (above
left). However, to identify which layer was supply-
ing water to the oil-producing zone required com-
parison with the produced water. There were no
pH measurements on the previously produced
water, but laboratory analysis on stock tank sam-
ples provided ion concentrations for the waters
from the existing producers, and these were com-
pared with concentrations from the waters sam-
pled in the new well.
Scientists used a graphical method called a
“Stiff diagram” to compare the compositions of
the various water sources.28 Each plot shows the
relative concentrations of anions and cations fora particular water sample, scaled in milliequiva-
lents per liter (meq) (left).29 All samples of the
produced water showed a similar pattern.
However, samples from the new well exhibited
differences. The samples from Zones 2 and 3 had
patterns resembling those of the produced water,
while Zones 4 and 6 contained waters with dis-
tinctly different compositions.
> Fluid sampling data. In a well drilled with OBM to facilitate water sampling, ADCO collected fluids
from five of six carbonate zones. The water in Zone 4 is clearly different from that in the otherwater-filled zones. The water from Zone 6 may be different from the water in Zone 3; these data werecombined with those shown below and on the next page to determine the source of water producedfrom Zone 2.
1 Oil Oil sample High
HighOWC delineationOil and water2
Water 6.5 6.61 mD to 10 mDpH, water sample3
Water Less than 1 mD 7.3 7.8pH, water sample4
Water Too tight to flowNone5
Water 6 6.3Less than 1 mDpH, water sample6
Zone Fluid Measurement Permeability Downhole pH Modeled pH
> Comparing water compositions. Stiff diagrams allow visual identificationof similarities and differences between water samples. Concentrations ofcations are plotted to the left of the vertical axis, and concentrations ofanions are plotted to the right. Compositions of water samples from theproducing wells (top ) are all similar, whereas compositions of samples from the new well (bottom ) show large variability. The waters from Zones 2 and 3are similar to the produced water, but the compositions of samples fromZones 4 and 6 are different in most cations and anions.
Na+K/1,000 Cl/1,000
Sulfate/10Ca/100
–10 –8 –6 –4 –2 2 4 60
Carbonate/10
meq
Mg/10
Na+K/1,000 Cl/1,000
Sulfate/10Ca/100
–10 –8 –6 –4 –2 2 4 60
Carbonate/10
meq
Mg/10
Oil producersZone 2Zone 3Zone 4Zone 6
Oil producers
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Spring 2011 33
Isotopic analysis corroborated the composi-
tional information. A plot of hydrogen and oxygen
isotope ratios for samples from the new well con-
firmed that the water from Zone 3 was similar to
that in Zone 2. Also, the waters from Zones 4 and
6 were quite different from each other and from
those of Zones 2 and 3 (above). Strontium isoto-
pic ratios were also different.
These analyses showed that Zone 3 is the
source of water produced in Zone 2—the oil-
producing layer—allowing ADCO engineers to
conclude that water sweep is from the flanks of
the reservoir, and there is no water support from
Zones 4 and 6, below the reservoir.
Laboratory Measurements on Live Waters
Traditional laboratory analysis is usually per-
formed on “dead” or stock tank water, and this
analysis may be useful for production surveil-
lance. However, during the initial exploration
and appraisal stages, when the operator builds
an understanding of the reservoir fluids and
uses that data for modeling water chemistry atreservoir and pipeline conditions, it is critical to
work on representative live-water samples.
Through downhole fluid analysis, specialists
are able to perform direct measurements on live
fluids—fluids that still contain dissolved gas—
at reservoir conditions. Furthermore, sample-
collection technology, which has the ability to
monitor contamination and maintain water sam-
ples at elevated pressure, allows operators to
bring live fluids to the surface and transport
them intact to a laboratory.
In the laboratory, the collected water samples
are reconditioned to downhole temperature and
pressure, encouraging any gases and solids that
have come out of solution to redissolve. The sam-
ples are flashed—the sample bottles are opened
and the fluids are exposed to surface pressure
and temperature—before laboratory analysis.
Laboratory specialists measure the gas/water
ratio (GWR) and perform gas chromatography to
analyze the composition of the liberated gas.
They also analyze ion composition, pH and low–
molecular weight organic acids in the water
phase. A more rigorous process employed by
some operators involves partitioning the flashed
water sample into three parts. Acid is added to
one part of the sample to preserve cations, which
are then analyzed by inductively coupled plasma
(ICP). Sodium hydroxide is added to the second
part to preserve organic acids, which are then
analyzed by ion chromatography. The third por
tion is kept untreated and is used to measure
density, pH, conductivity, alkalinity (by titration
and anions by ion chromatography.
For the most part, commercial laboratorie
have not been equipped to directly analyze live
water at reservoir conditions, but some are mak
ing advances in this direction. Schlumberger sci
entists have developed a new laboratory technique
for measuring pH of live formation water samples
at reservoir temperature and pressure.30 The sam
ple remains in the pressurized bottle in which i
was brought to the surface. A heated jacket bring
the bottle to reservoir temperature. As the water
sample flows through a pressurized flowline—
which is similar to the tool flowline—it mixe
with the same dye used in the downhole measure
ment, and the fluid mixture passes through a
spectrometer that analyzes the color.
Comparison of the laboratory pH measure
ment with the real-time in situ pH measure
ments made on the same formation water allows
27. Carnegie AJG, Raghuraman B, Xian C, Stewart L,Gustavson G, Abdou M, Al Hosani A, Dawoud A,El Mahdi A and Ruefer S: “Applications of Real TimeDownhole pH Measurements,” paper IPTC 10883,presented at the International Petroleum TechnologyConference, Doha, Qatar, November 21–23, 2005.
28. Stiff HA: “Interpretation of Chemical Water Analysis byMeans of Patterns,” Transactions of the AmericanInstitute of Mining and Metallurgical Engineers 192 (1951):376–378. [Also published as paper SPE 951376 andreprinted in Journal of Petroleum Technology 3, no. 10(October 1951): 15–17.]
Z o n e
Zone 3 Zone 2
Zone 6
Zone 4Zone 2
87Sr/86Sr
Zone 3
Zone 4
Zone 6
2
3
4
5
6
0.7074 0.7076 0.7078 0.7080
–10
10
–5 5δ
18OSMOW
δ D S M O W
δ = R sample × 1,000
R standard
– 1
R sample = ratio of heavy to
light isotope in the sample
R standard = ratio of heavy to
light isotope in standard
mean ocean water (SMOW)
> Isotopic analysis of water samples from the new ADCO well. Many elements have isotopes, or atomswith different atomic weights. The most common form of hydrogen (with one proton) has an atomicweight of 1, and is written as 1H. A less common isotope, 2H, with one proton and one neutron, isusually written as D, for deuterium. Similarly, oxygen has three isotopes, 16O, 17O and 18O. Isotopes havesimilar chemical properties but different physical properties. For example, they “fractionate” duringevaporation and condensation, leaving water enriched in heavy isotopes. Comparing ratios ofhydrogen and oxygen isotopes is a common method to distinguish waters from different sources. In the ADCO case, analysis shows that the water in Zone 4 is different from those in the other zones (left ).Comparison of strontium [Sr] isotope ratios (right ) is another technique for highlighting differencesbetween water sources. Here, waters from Zones 4 and 6 are significantly different from those in
Zones 2 and 3.
29. An equivalent is the amount of a material that will reactwith a mole of OH– or H+. A milliequivalent is anequivalent/1,000.
30. Mathews SG, Raghuraman B, Rosiere DW, Wei W,Colacelli S and Rehman HA: “Laboratory Measurementof pH of Live Waters at High Temperatures andPressures,” paper SPE 121695, presented at the SPEInternational Symposium on Oilfield Chemistry, TheWoodlands, Texas, USA, April 20–22, 2009.
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34 Oilfield Review
fluid analysts to validate the integrity of the
sample. A good match indicates the sample is
still representative of the formation water.
Sample validation in this manner is an imple-
mentation of the “chain of custody” concept.31
The laboratory setup also allows chemists to
measure the live-water pH as a function of tem-
perature and pressure and flag the onset of
scale precipitation. These additional measure-
ments can be used to better constrain and tune
water-chemistry models.Chevron tested this technique on formation
water samples from two Gulf of Mexico wells.32 In
Well A, the zone of interest is a thick, permeable
water zone—a potential supply for injection
water—thousands of feet above the reservoir. The
company wanted to assess the corrosion potential
of the water and evaluate its compatibility with
the reservoir formation water. Downhole mea-
surements of pH were made and samples were
collected at two depths. Laboratory measure-
ments matched the downhole measurements to
within 0.08 pH units, giving Chevron chemists
confidence that the reconditioned live samples
were representative of formation water.
Comparison with predictions from two differ-
ent simulators indicated a good match (within
0.15 units) for one sample. For the second sam-
ple, the discrepancies were larger, not just
between predicted and measured values, but alsobetween the two commercial models used for the
simulation (0.24 to 0.65 units). The reasons for
the differences in predicted values from the two
simulators are due to the different thermody-
namic databases upon which they are based, as
well as the different approaches to using the
inputs in modeling. The differences highlight the
uncertainties that can arise when flashed water
analysis is used as input to simulators and under-
score the importance of direct measurements on
live waters to constrain and tune the models.
In Well B, the zone of interest is a water-rich
interval beneath the oil target; it is considered to
be a potential source of water cut sometime in
the future life of the field. The pH of this water
may have sizeable impact on equipment design,
selection and costs.Live-water pH measurements were performed
at the in situ temperature of 242°F [117°C] and
pressure of 19,542 psi [134.7 MPa], and then at
pressures down to 8,000 psi [55 MPa] to test the
sensitivity of the measurement to pressure (left).
Fluid analysts monitored the optical signal dur-
ing this change in pressure and did not detect
any solid precipitation from scale onset or gas
evolution that would have caused light scatter-
ing. This indicates that the water stayed as a sin-
gle phase all the way from reservoir pressure
down to 8,000 psi. The ability to measure pH and
track scale onset with pressure and temperature
in this setup makes it a potentially powerful
method to collect data for tuning and improving
confidence in water chemistry simulator models.
Other Fluid Measurements
Downhole fluid analysis currently can quantify
many fluid properties in situ, including pressure,
temperature, resistivity, density, composition,
gas/oil ratio, pH, fluorescence and optical den-
sity. Although most of these fluid property mea-
surements were originally designed with
hydrocarbons in mind, several of them—in addi-
tion to pH—may be applied to analysis of forma-
tion water.
Recently, a downhole fluid density measure-
ment was tested as an alternative to pH for
detecting WBM contamination and oil/water
contacts. The InSitu Density sensor is a tiny
vibrating rod—a mechanical resonator—in the
tool flowline. The resonance frequency of the rod
decreases as the fluid density increases. The den-
sity measurement is useful when the pH of the
WBM is similar to that of the formation water.
Another advantage is that density measurements
may aid in fluid typing in cases that are problem-atic for pressure-gradient interpretation of fluid
contacts, such as thin beds, low-permeability for-
mations and poor-condition wellbores.
The InSitu Density device has been used for
downhole water analysis in WBM-drilled wells off-
shore Vietnam, Norway and China.33 Applications
include monitoring contamination cleanup before
collecting water samples, analyzing formation
> High-pressure, high-temperature (HPHT) laboratory measurements of pH. Schlumberger scientistsperformed pH measurements on live waters at reservoir pressure and temperature (19,542 psi and242°F) and at a range of pressures down to 8,000 psi (bottom ). The optical spectrum of the aqueoussystem was measured using probes connected to an HPHT scanning cell (top right ). Optical signalmonitoring (top left ) indicated that water stayed in single phase down to 8,000 psi with no scale onset.The pH measurement is calibrated only to 10,000 psi: The scarcity of thermodynamic data in theliterature makes calibration difficult and uncertain at pressures greater than that. In this figure,calibration parameters for 10,000 psi are used for the data at pressures of 10,000 psi and greater,which are indicated by a dashed line.
p H
Pressure, psi
8,000 12,000 16,000 20,000
6.3
6.2
6.1
6.0
5.9
5.8
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S i 2011 35
water for future reinjection with seawater, evalu-
ating of reservoir vertical connectivity and assess-
ing flow assurance in pipelines and flow streams
to be tied back to processing equipment on a
main platform.
In an exploration example from offshore
China, pressure pretests in five sands yielded
inconclusive fluid-typing results in all but the
deepest zone, Sand E, which had a pressure gra-
dient indicative of oil. Only one pressure reading
could be obtained from each of Sands A, B and C,
so it was impossible to compute gradients in
those zones. The gradient from the two pressures
measured in Sand D corresponded to the mud
density, indicating whole-mud invasion. Optical
analysis of fluids pumped from the five sands gave
additional but surprising information: Sands A
and C produced water, and Sands B and D pro-duced oil. Real-time downhole fluid density mea-
surements on these same fluids corroborated the
optical and pressure analyses and helped deter-
mine the free-water level in Sand B (above).
The number of fluid analysis measurements
that can be made in situ is increasing. Current
capabilities have been likened to having a down-
hole fluids laboratory.34 Undoubtedly some of the
new measurements will find applications to for
mation water analysis, increasing the ability o
oil and gas companies to understand their reser
voirs, optimize completions, select materials and
monitor water injection.
Extending the array of downhole measure
ments will likely force high-pressure, high
temperature laboratory techniques to keep pace
Currently, high-accuracy pH measurements canbe made both in situ and at similar conditions in
the laboratory. In the future, additional analyse
will extract even more information and value
from formation water. —LS
> Looking for fluid contacts. Fluid densities interpreted from gradients inpressure measurements (left ) in five sands indicated oil only in the deepestzone, Sand E (below 2,200 m). Pressure measurements (dots) are color-coded based on quality: green is high and yellow is satisfactory. In Sand D,around 2,100 m, the gradient suggests a fluid heavier than water, such asdrilling mud. Optical characterization (middle, Depth Track) of the fluids
pumped from Sands A and C identified these intervals as water-pronelayers (blue shading in Depth Track); Sands B and D contain oil (green
shading in Depth Track). Measurements from the InSitu Density tool giveprecise density values (gray shaded) for these fluids, values that can beextended along pressure gradients. In an expanded view (right ), gradientanalysis helps interpreters understand reservoir architecture. Theintersection of the water gradient in Sand C (lower blue line) with the oilgradient in Sand B (green line) identifies the free-water level in Sand B at
1,693.5 m. The nonintersection (dashed circle) of the water gradientsconfirms the lack of communication between Sand B and Sand A.
Formation Pressure, psi
Pretest Quality Pretest Quality
Gamma Ray
Sand ASand A
Sand B
Sand C
Sand B
Sand C
Sand D
Sand E
Dry Test
0
2,200 3,200
gAPI 250
1,600
1,600
1,700
1,700
1,800
1,900
2,000
2,100
2,200
Lost Seal
Depth,m
FluidFraction
Formation Pressure, psi
Gamma Ray
Dry Test
0
2,200 3,200
gAPI 250
Lost Seal
Depth,m
FluidFraction
1.3545 g/cm3 (mud)
1.0124 g/cm3 (water)
1.0195 g/cm3 (water)
0.8859 g/cm3 (oil)
0.7807 g/cm3 (oil)0.8929 g/cm3 (oil)
0.8859 g/cm3 (oil)
1.0124 g/cm3 (water)
Free-water level: 1,693.5 m
1.0195 g/cm3 (water)
Pretest Quality
Formation Pressure, psi
Gamma Ray
Dry Test
0
2,200 3,200
gAPI 250
Lost Seal
1.3545 g/cm3 (mud)
0.7807 g/cm3 (oil)
31. Betancourt SS, Bracey J, Gustavson G, Mathews SGand Mullins OC: “Chain of Custody for Samples of LiveCrude Oil Using Visible-Near-Infrared Spectroscopy,”Applied Spectroscopy 60, no. 12 (2006): 1482–1487.
32. Mathews et al, reference 30.
33. Mas C, Ardilla M and Khong CK: “Downhole FluidDensity for Water-Base Mud Formation-Water Samplingwith Wireline Formation Tester,” paper IPTC 13269,presented at the International Petroleum TechnologyConference, Doha, Qatar, December 7–9, 2009.
34. Creek et al, reference 18.